In most gas processing facilities, the amine treating unit, such as an amine contactor and amine regeneration unit, is a continuous processing unit that removes acid gases from a hydrocarbon gas stream. The primary acid gases to be removed are hydrogen sulfide and carbon dioxide. Acid gases are commonly removed by contacting the hydrocarbon stream with an aqueous organic amine such as monoethanolamine (MEA), diethanolamine (DEA), methyldiethanolamine (MDEA), diisopropanolamine (DTPA), diglycolamine (DGA) triethanolamine (TEA) or others diluted in water as an aqueous amine solution. The amine solution chemically reacts with and/or physically absorbs the acid gases in an absorber (amine contactor). In the absorber, the acid gases in the hydrocarbon gas stream are removed and a sweetened gas stream and an amine solution rich in the absorbed acid gases (rich amine) at high pressure are produced. The rich amine is then introduced to an amine flash tank through a pressure reduction device to remove the light hydrocarbons with some acid gases at a much lower pressure. The amine-acid gas interaction is later reversed in a low pressure and high temperature stripper (amine regenerator), resulting in a wet acid gas stream and a reusable solvent stream (lean amine).
In an amine unit, foaming in the absorber and regenerator is a common problem due to liquid hydrocarbon contamination and other particulates in amine solution. A portion of heavier hydrocarbon components in the absorber feed gas will be absorbed by the amine solution. Foaming is likely to occur due to the low surface tension of the independent liquid hydrocarbon in the rich amine. For example, due to significant shearing by pressure letdown of the rich amine via a Joule-Thompson (JT) valve, foaming frequently occurs. The residence time of the aqueous organic amine stream in the amine flash tank may not be sufficient to allow resolution or breaking of foaming. In addition, in the two-phase rich amine after pressure letdown, the flash gas can expand from a liquid to a vapor causing uncontrollable foaming. The formation of foam in the amine flash tank or stripper unit is undesirable and can overwhelm the separation process in the tank or stripper. The formation of foam can lead to treating capacity constraints, excessive amine losses due to carryover of amine to downstream processes, off-specification products (lean amine and/or treated gas), resulting in reducing the operating rate of the unit, producing unspecified dark sulfur, increasing fouling within the lean/rich amine exchanger, and/or increasing the pressure drop within the unit. If a major foaming occurs, not only is there excessive amine carryover to downstream mol-sieve dehydration unit, but also a significant amount of carbon dioxide (CO2) will be carried into the cryogenic section; in particular, for the hydrocarbon gas with high CO2 content. Under both scenarios, the LNG plant may be partially or totally shut down to troubleshoot the mol-sieve dehydration uint and/or defrost the cryogenic section of the plant, resulting in a negative impact on LNG production. Typical attempts to control foaming in the stripper include the use of antifoams (silicone and nonsilicones), increasing the aqueous amine stream temperature, and/or installation of a bigger flash drum. While such methods exhibit some efficacy, they are usually only partially successful in addressing downstream operating problems or are costly to implement. For example, continuous addition of antifoams to solve the foaming problem may lead to further worsening problem, unstable operations, and increased operational expenditure.